An integrated reservoir zonation in sequence stratigraphic framework: A case from the Dezful Embayment, Zagros, Iran

Author’s Accepted Manuscript An integrated reservoir zonation in sequence stratigraphic framework: A case from the Dezful Embayment, Zagros, Iran Mehdi Daraei, Aram Bayet-Goll, Morteza Ansari www.elsevier.com/locate/petrol

PII: DOI: Reference:

S0920-4105(16)31151-2 http://dx.doi.org/10.1016/j.petrol.2017.04.038 PETROL3978

To appear in: Journal of Petroleum Science and Engineering Received date: 29 November 2016 Revised date: 16 March 2017 Accepted date: 26 April 2017 Cite this article as: Mehdi Daraei, Aram Bayet-Goll and Morteza Ansari, An integrated reservoir zonation in sequence stratigraphic framework: A case from the Dezful Embayment, Zagros, Iran, Journal of Petroleum Science and Engineering, http://dx.doi.org/10.1016/j.petrol.2017.04.038 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting galley proof before it is published in its final citable form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

An integrated reservoir zonation in sequence stratigraphic framework: a case from the Dezful Embayment, Zagros, Iran Mehdi Daraeia*, Aram Bayet-Golla, Morteza Ansarib a

Department of Earth Sciences, Institute for Advanced Studies in Basic Sciences (IASBS), Zanjan, Iran

b

Geology and Geophysics group, Abdal Industrial Projects Management Company (MAPSA), Tehran, Iran

[email protected] [email protected] *

Corresponding author.

Abstract This study focuses on reservoir rock typing of the Oligo-Miocene Asmari Formation in order to introduce a field-scaled reservoir zonation for the strata in one petroleum field of SW Iran, where the formation is composed of mixed marginal marine sand/sandstones and shallow marine carbonates, capped by the evaporite-bearing Gachsaran Formation. On the way, sedimentary and diagenetic aspects of the formation are presented to characterize the main geologic factors controlling reservoir attributes of the petroleum field. Then, an integration of three different reservoir rock classification methods is applied to identify speed and/or baffle zones of the reservoir. Based on the results, the main speed zones of the field are comparable to the siliciclastics of the reservoir whose distribution is the product of sea-level-controlled terrigenous supply to the basin. Although the carbonates have high storage capacity owing to noticeable early diagenetic dissolution, they possess low flow capacity due to isolated network of pore spaces; therefore, they make the baffle zones of the field. The five reservoir zones determined can be located in other parts of the field via well logs and/or the sequence stratigraphic framework. Keywords: Reservoir rock classification; reservoir zonation; Asmari Formation; Dezful Embayment; Iran

1

1. Introduction One important challenge for geologists and reservoir engineers is to enhance the reservoir description methods for achieving more oil recovery and the least residual oil. These methods attempt to explore various reservoir rock types, each with distinct petrophysical properties and same geologic adventure to characterize the reservoir properties (Archie, 1950). The methods include simple ones that try to infer porosity-permeability relationship with a simple cross plot of porosity versus permeability and then extrapolating it to other parts of a field, to lithofacies-based methods, to more sophisticated engineering methods (e.g., Hearn et al., 1983; Ebanks Jr, 1987; Ebanks Jr et al., 1993; Lucia, 1995; Gunter et al., 1997a; Gunter et al., 1997b; Martin et al., 1997; Hamon and Bennes, 2004; Masaimeh et al., 2007; Masalmeh and Jing, 2007; Clerke, 2010). Nowadays, attempts to unravel complex porethroat geometries in various sedimentary facies is a clue for reservoir description and classification of reservoir rocks (Lucia, 1995). The Oligo-Miocene Asmari Formation is the most important reservoir rock of Iran that hosts more than 90% of recoverable oil of the country (Ghazban, 2007). Huge hydrocarbon reserve, being the first oil discovery place of the world and vast investigations gave a global reputation to the formation. This formation is shallow-marine carbonate in origin, but locally, two distinct evaporite and siliciclastic members occur in it (James and Wynd, 1965). The siliciclastic member is equivalent to the Ghar Formation of Iraq and Kuwait (Alsharhan and Nairn, 1997; Ziegler, 2001). In spite of vast studies conducted on various aspects of the formation (e.g., Busk and Mayo, 1918; Lees, 1933; James and Wynd, 1965; Adams and Bourgeois, 1967; Adams, 1969; McQuillan, 1985; Seyrafian, 2000; Aqrawi et al., 2006; Laursen et al., 2006; Vaziri-Moghaddam et al., 2006; Amirshahkarami et al., 2007; Ehrenberg et al., 2007; Laursen et al., 2009; Mossadegh et al., 2009; van Buchem et al., 2010; Kavoosi and Sherkati, 2012), a little has been targeted on the reservoir characterization of the formation (e.g., Honarmand and Amini, 2012; Gharechelou et al., 2016). In addition, based on our knowledge, there is no published work regarding reservoir rock typing of the strata. Consequently, we focus on this neglected aspect of the formation in one hydrocarbon field. The

2

Cheshmeh-Kush (CK) Field is located in SW Iran (Ilam province) in a tectonostratigraphic zone referred to as the Dezful Embayment, which hosts much hydrocarbon of Iran. Here, the formation produces both oil and gas, and is composed of mixed siliciclastics and carbonates. In this study, we try (1) to introduce an integrated reservoir zonation for the rocks based on three different reservoir rock typing methods, then (2) to verify the zonation in the sequence stratigraphic framework of the field to establish a context for correlating the reservoir zones in other parts of the field and possibly in other fields of SW Iran, as well as to investigate if the reservoir characteristics were affected by sea-level fluctuations.

2. Geological framework The most prolific strata of Iran are located in the Zagros Orogen. The orogen is the product of stillactive continental collision between the NE margin of the Arabian Plate and Iranian plates after a complex sea-floor spreading (Neothetys Ocean creation) and succeeding subduction. It includes several NW–SE trending structural zones from the NE toward SW (Stocklin, 1968; Takin, 1972; Haynes and McQuillan, 1974; Berberian and King, 1981; Jackson and McKenzie, 1984; Alavi, 1994; Alavi, 2004; Alavi, 2007). Among these zones, the Zagros Fold-Thrust Belt (ZFTB), as the outer zone and the northeastern margin of the Arabian Plate, forms 200–300 km-wide series of remarkable folds extending for ~1200 km from eastern Turkey to the Strait of Hormuz (Alavi, 2004; Ahmadhadi et al., 2007; Alavi, 2007) (Fig. 1A). This folded belt hosts huge hydrocarbon fields of the region and mainly developed during the Mio-Pliocene time, ~7 to 3 Ma ago (Falcon, 1961; Berberian and King, 1981; Stoneley, 1981; Homke et al., 2004). Most hydrocarbons were trapped in anticlines of the ZFTB during the late Miocene-Holocene (Ala, 1982). This folded belt is itself subdivided by major faults of the Zagros Orogen into several semi-lateral tectonostratigraphic zones, each with distinct history of sediment accumulation (Stocklin, 1968; Falcon, 1974; Berberian and King, 1981; Motiei, 1993): The Kirkuk Embayment, Dezful Embayment, and Lurestan, Izeh, and Fars zones (Fig. 1A).

3

By the Cenozoic, the continental collision between the Arabian Plate and Iranian plates gave rise to the flexure of the NE margin of the Arabian Plate and the creation of a syn-collision peripheral foreland basin across the today Zagros Orogen (Fig. 3a) (Beydoun et al., 1992; Alavi, 1994; Dercourt et al., 2000; Sharland, 2001; Alavi, 2004; Sepehr and Cosgrove, 2004; Sherkati and Letouzey, 2004; Heydari, 2008). The Oligo-Miocene Asmari Formation represents the last carbonate depositional phase in such a basin, which was deposited during its latest tectonosedimentary megasequence (megasequence XI of Alavi (2004) and TMS AP11 of Sharland (2001)). It is believed that the formation was deposited in a narrow NW-SE trending carbonate platform under tropical arid conditions (e.g., Adams and Bourgeois, 1967; Ehrenberg et al., 2007; Heydari, 2008). The Asmari Formation in its type section and many other localities is almost entirely carbonate in origin, but two other distinct mixed lithologies are also present (Fig. 1C); In NW Zagros/SW Lurestan, it is composed of a mixed evaporite and carbonate succession known as the ‘Kalhur Evaporite Member’, whereas in SW Zagros/Dezful Embayment, of mixed siliciclastics and carbonates, referred to as the ‘Ahwaz Sandstone Member’ (James and Wynd, 1965). The formation mostly overlays pelagic facies of the Pabdeh Formation and underlays costal to continental facies of the Gachsaran Formation that acts as cap rock for the formation in hydrocarbon fields of Iran.

3. Database and methods This study was established mostly upon data from 12 wells of the Cheshmeh-Khush oil field in the Dezful Embayment, where the Asmari Formation is composed of siliciclastics in its lower part and carbonates in the upper part (Fig. 1). Direct petrophysical and sedimentological (thin sections) data were available form two wells (wellCK#8 & wellCK#12) including 908 poro-perm data and nearly 600 core slabs. Thin sections were prepared from the core slabs and stained using standard procedures (Dickson, 1965), among which 198 samples were impregnated by blue-dyed resin to investigate pore space aspects. Apart from these subsurface sections, sedimentologic data from six surface sections located in the SW Lurestan Zone were in hand (Fig. 1B), providing good information about temporal

4

and spatial distribution of the sedimentary characterizes across the Zagros Mountains. The thin sections were studied using polarizing microscope for petrographic considerations. The nomenclature of the facies recognized carried out using Dunham (1962) and Embry and Klovan (1971) schemes. Moreover, the paleosedimentary interpretation was done by comparing to well-known and standard facies models ( ). Sequence stratigraphic framework was established by using the method proposed by Hunt and Tucker (1992). Three different methods were used for the reservoir characterization and rock typing: Reservoir Quality Index (RQI), Lucia’ petrophysical classification and stratigraphic modified Lorenz Plot (SMLP). The details of the methods are discussed in the subsections 4.4.1.1, 4.4.2.1 and 4.4.3.1, respectively.

4. Results 4.1. Sedimentary facies and paleoenvironment Field observations revealed the Asmari Formation consists of three fundamental lithofacies: omnipresent carbonates, together with local evaporites and siliciclastic sands/sandstones. Petrographic studies show these lithofacies can be subdivided into one evaporite microfacies (MF-1), nine carbonate microfacies (MF-2-10) and one siliciclastic petrofacies (PF-1) as shown in Table 1. Photomicrographs of the facies are represented in Fig 2. Table 1. Facies recognized in the Asmari Formation across the study area and their geologic attributes. Facies Code

Facies Name

Main Components

Depositional Setting

MF-1

Evaporite

Gypsum phenocrysts

Basinwide evaporites

MF-2

Stromatolite (dolo) boundstone

Blue- green algae

Peritidal

MF-3

Bioclast wackestone

Molluska, echinoids, miliolids

Lagoon

MF-4

Small hyaline benthic foraminifera (SBF) mud-wackestone

Small hyaline benthic foraminifera

Lagoon

5

MF-5

Ostracoda oyster floatstone-rudstone

Oyster, ostracoda

Lagoon

MF-6

Ooid (dolo) grainstone

Ooid

Marginal shoal

MF-7

(Coralline algae) foraminifera (dolo) packstone

Coralline algae, porcelaneous foraminifera

Subtidal (lagoon to off-shoal subtidal)

MF-8

Coralline algae bindstone

Coralline red algae

Proximal middle ramp

MF-9

(Coralline algae) larger benthic foraminifera (LBF) floatstone-bindstone

LBF, SBF, textularids, valvulinds

Distal middle ramp

MF-10

Planktonic Foraminifera wackestone

Planktonic foraminifera

Outer ramp

PF-1

Siliciclastic sand/Quartzarenite

Quartz

Marginal marine (siliciclastic delta)

Spatial and temporal distribution of the facies and their comparison with standard microfacies suggest the Asmari Formation was deposited in three different, but interrelated depositional systems (Fig. 3). Much of the deposition occurred in a narrow NW-SE trending shallow carbonate ramp, where the Zagros Mountain is extended nowadays. Nevertheless, this dominant depositional setting had locally two other different depositional sites: The one, which was located in present-day Lurestan Zone, was an intrashelf sub-basin (Kalhur Sub-basin) favored the precipitation of evaporites during lowered sea level but carbonates during raised sea level. This sub-basin was created due to the reactivation of some basement faults at the time, and was where sea-level fluctuations resulted in alternative dissecting and reconnecting to open seas thus alternate deposition of evaporites and carbonates (Daraei et al., 2015). In the SW margin of the Asmari Basin, the other depositional system (Ahwaz deltaic system/sub-basin) was generated owing to the infiltration of siliciclastics derived from the erosion of pre-rift highlands of the Red Sea to the basin (Ziegler, 2001). They produced a marginal siliciclastic sub-basin (a delta) in which the deposition of siliciclastic and carbonate sediments occurred alternatively, again because of sea-level fluctuation.

4.2. Diagenesis The most effective diagenetic processes occurred in the CK Field are micritization, dolomitization, dissolution, cementation, mechanical and chemical compaction and rarely tectonic fracturing.

6

Micritization is well-observed in the ooid grainstone facies (MF-6), and bioclastic wackepackstones of lagoon and shallow subtidal settings (MF-3-5, MF-7), resulting in obliterating primary fabrics in the former and developing micritic envelops in the latter (Fig. 4a-c). Consequently, the ooids became more susceptible to the later dolomitization, whereas the biocalsts developed moldic pore spaces after dissolving their unstable interiors. Dolomitization is presumably the most pervasive diagenetic process, highly impacting the reservoir quality of the formation (Aqrawi et al., 2006). It has occurred in both replacing and cementing forms (Fig. 4c-d, g, h), and the intensity of the process increases successively upward, pointing to consecutive decrease in the accommodation space up to the formation. Apart from the lower half of the formation, where the rocks were affected by dolomitizing fluids from the underlying Pabdeh Formation, an evaporative mechanism (sabkha and seepage-reflux models) is considered as the main dolomitization context for the formation. Evidence such as more common dolomitization in inner platform facies than the distal ones, the domination of evaporate signature in geochemical properties of the dolomites, the co-occurrence of dolomites with evaporite nodules and cements, the existence of highly saline fluid inclusions in the dolomites supports this interpretation (Aqrawi et al., 2006). Dissolution mostly resulted in creating moldic (vuggy sensu Lucia (1983)) pore spaces in the field. The spaces are then filled with iron-free early diagenetic cements, mostly of dolomite mineralogy, indicating an early diagenetic origin for the porosity-enhancing process. The process is observed in the oolitic facies (MF-6) by developing oomolds and in the bioclastic facies by biomolds (MF-3-5) (Fig. 4c, f, g). Cementation has occurred by calcite, dolomite and sulfate cements, among which the dolomite is more frequent (Fig. 4g-l, a). The calcite cement, mostly occurring as equant and drusy fabrics, seems to be the least frequent cement. The most common cement is dolomite, mostly showing fine to medium crystal sizes. Isotopic composition and textural relationships indicate the cement is of evaporative and early diagenetic origin (Aqrawi et al., 2006). The sulfate cement (mostly anhydrite) is the most affecting cements, in reservoir quality point of view. Where the cement has occurred, the 7

quality is decreased drastically. It normally is the last generation of cementation in the pores and, in places, fills the remnant space, which formerly lined by fine to medium sized dolomite cement (Fig. 4k). The evaporite cement is commonly observed with patchy and poikilotopic fabrics, somewhere with even distribution, the latter significantly reducing the porosity (cf., Lucia, 2007). Compaction has occurred in both mechanical and chemical forms. Repacked, distorted, rotated and broken grains are evidence for mechanical compaction in the formation. The chemical compaction is commonly observed as fitted fabrics and stylolites, so that the former is a common aspect of the oolitic facies (MF-6; Fig. 4l). Although Fracturing is one of the important factors enhancing the quality of the Asmari reservoirs across the Zagros (McQuillan, 1985), it has had a little impact on the studied filed due to the low occurrence. However, where presents, it resulted in a high reservoir quality. Yet, the prevalence of fracturing in the Asmari Formation across the Zagros Mountain places it in the Fractured Reservoirs group of the world. Based on this study, the Asmari Formation in the studied field experienced a normal diagenetic sequence during which the formation passed through marine, meteoric and burial environments, respectively (Fig. 5). Diagenetic processes and environments have had a superior role in altering primary sedimentary characteristics of the Asmari carbonates, leading to high heterogeneity of the carbonate part. It seems the porosity of the carbonate rocks has increased owing to vast dissolution, but the pores commonly make an isolated network (moldic & vuggy), except for areas where fracturing has taken place. The sulfate cementation is, in contrary, the most effective porosityoccluding process.

4.3. Sequence stratigraphy The Asmari Formation in this field consists of four complete stratigraphic sequences as well as a falling stage systems tract (FSST) in its lower part (Fig. 6). The main point is that the lower and upper sand/sandstone units are the product of the FSST. During these episodes, the lowered sea level 8

resulted in the entrance of huge volume of sands from the Arabian Plate into the Asmari Basin, producing the Ahwaz Sandstone Member. A comparison between the sequences identified in SW Zagros/CK Field with those of NW Zagros/SW Lurestan Zone is illustrated in Fig. 6. As seen, the deposition of the Asmari Formation in the studied field started some time before the Kalhur evaporitic sub-basin. The Roman-numbered sequence partitioning surfaces in Fig. 6 are those proposed by van Buchem et al. (2010).

4.4. Reservoir rock typing 4.4.1. Flow zone indicator (FZI) method 4.4.1.1. Theoretical framework If a porous media is regarded as a bundle of straight capillary tubes, the following equation with the fD

’

wf

f w

p

’

wf

f w

b

b

:

(1) Where k – permeability, r – pore radius and

e

– effective porosity.

This simple but important equation shows the connection of permeability to porosity, or hydraulic behavior of a rock depends on the pore throat properties, primarily controlled by geological sedimentary and/or post-sedimentary factors. In a real porous media, equation (1) can be rewrite as equation (2) (Kozeny, 1927; Carman, 1937):

(2)

Where τ is tortuosity, Fs is the shape factor and Sgv is the surface area per unit grain volume. The sophisticated problem in this equation is the term

in which the Kozeny constant,

, is a number between 5 and 100, but normally is supposed to be 5, and

is usually neglected.

However, both of them are dependent on geological features of rocks and should be regarded. The 9

Flow Zone Indicator (FZI) method is a successful and precise method in which the problems of equation (2) are addressed (Amaefule et al., 1993; Abbaszadeh et al., 1996). The equation can be rewritten by changing the unit of permeability from μm2 to mD:

√

(3)

Now, we can define two parameters called Flow Zone Indicator (FZI) and Reservoir Quality Index (RQI), respectively as: (4)

√

(5)

Substituting equations (4) and (5) in equation (3) gives: (6) Alternatively: (7) Therefore, with a logarithmic diagram, where RQI is plotted against Phiz ( z), we can obtain FZI or (

). In other words, we can distinguish rocks with similar geologic journey, sharing same

petrophysical aspects (rock types). For declustring of data on the diagram, there are numerous mathematical and statistical methods.

4.4.1.2. Hydraulic flow zones in the CK Field In this study, we have used two simple graphical methods for declustring of the FZI data: histogram analysis and probability diagram (Table 2; Fig. 7).

10

Table 2. An example of primitive parameters and calculations required for identifying hydraulic flow zones base on RQI method, wellCK#8, CK Field. Depth

Porosity

Poro(v/v)

K

RQI

øz

FZI

Log FZI

3425.4

4.3

0.043

0.06

0.037

0.045

0.83

-0.1

3425.47

6

0.06

0.04

0.026

0.064

0.40

-0.4

3425.63

3.2

0.032

0.08

0.050

0.033

1.50

0.2

3426.42

11.6

0.116

21

0.422

0.131

3.22

0.5

3426.52

5.8

0.058

0.12

0.045

0.062

0.73

-0.1

3426.69

5.5

0.055

0.08

0.038

0.058

0.65

-0.2

3426.94

3.1

0.031

0.56

0.133

0.032

4.17

0.6

3427.12

11.7

0.117

0.26

0.047

0.133

0.35

-0.5

3427.19

10.9

0.109

1.81

0.128

0.122

1.05

0.0

3427.38

11.3

0.113

7.3

0.252

0.127

1.98

0.3

3427.57

14.8

0.148

15

0.316

0.174

1.82

0.3

3427.65

11.5

0.115

2.54

0.148

0.130

1.14

0.1

3427.82

8.7

0.087

4.43

0.224

0.095

2.35

0.4

3428.07

6.8

0.068

1.84

0.163

0.073

2.24

0.3

As seen, there are five hydraulic flow zones in the wellCK#8 and three ones in the wellCK#12. The logarithmic plot of RQI versus Phiz is illustrated in Fig 7e, f. Moreover, the relationship between porosity and permeability for each HFZ is shown in Fig. 8c, d. These relationships are different from that total poroperm relationship obtained in Fig. 8 a, b. Therefore, it can be concluded, for a real appraisal of quality in a reservoir, we firstly need to determine various hydraulic units, each representing a unique pore throat characteristic, then predict and extrapolate them across a field to be able to use poroperm equations properly.

4.4.2. Lucia’s petrophysical classification 4.4.2.1 Theoretical framework Petrophysical properties such as porosity, permeability and saturation are dependent rock properties derived from primary rock properties, that is, mineralogy, texture, grain packing, etc. (Ahr, 2008). These properties are interrelated through rock fabric, which itself is the product of the interaction

11

between sedimentary and post-sedimentary controlling factors. Therefore, for determining rock types in a reservoir, it is rational to consider these factors and avoid using petrophysical properties solely. Lucia’ petrophysical classification (Lucia, 1995; Lucia, 1999) is an attempt to consider the linkage between petrophysical aspects and rock fabric, where engineering and geological data are combined through a novel classification. It integrates Lucia’

petrophysical-based porosity

classification (Lucia, 1983) with Dunham’ geological-based textural classification for carbonate rocks (Dunham, 1962). The key concept in this classification is that the petrophysical properties of a reservoir are related to rock fabric through pore sizes. In this way, the pores in carbonate rocks are categorized into two broad categories: interparticle and vuggy. Rocks with interparticle pore spaces comprise three rock classes based on attributes such as their texture, being mud-dominated or graindominated, dolomite crystal size, sorting, mud and/or cement amount (cf., Lucia, 1995). Further, regarding the different behavior of rocks with vuggy porosity, they can be subdivided into two classes: those with separate vuggy porosity (SVC) and those with touching vug pore network (TVC). Geologic aspects of the petrophysical groups (PG) introduced by Lucia (1995) are presented in Table 3.

Table 3. Geologic and petrophysical properties of Lucia’ petrophysical groups.

PG

FABRIC

1

Graindominated

2

Graindominated

3 SVC TV C

Muddominated Grain- to muddominated Grain- to muddominated

MAIN PORE TYPE.

TEXTURE Grainstone; dolomitized grainstone; large crystalline dolostones Packstone; fine to medium crystalline dolopackstones; medium crystalline dolostones Pack-Mudstone; fine crystalline dolostones

Interparticle

1

Interparticle

2

Interparticle

3

VuggySeparate VuggyTouched

Any Any

12

QUALITY ORDER.

Variable VariableNormally high

4.4.2.2 Petrophysical groups in the CK Filed The presence of the Ahwaz Sandstone Member in the studied field necessitates adding other petrophysical groups to the Lucia scheme to consider the sandstones. The petrographical and petrophysical studies show these siliciclastic rocks can be categorized into the sand/sandstone petrophysical group (SC) and the mixed sandstones (MSC). Consequently, there are five petrophysical rock types in the carbonate part of the reservoir (Classes I, 2, 3, SVC and TVC) and two rock types in the siliciclastic part (SC & MSC). Petrophysical and statistical properties of these rock types are shown in Fig. 9 and Table 4, respectively.

Table 4. Statistical attributes of petrophysical classes recognized in the CK Field.

Data count PGs Class 1 Class 2 Class 3 SVC TVC SC MSC

Poro.

Perm.

29 24 206 78 60 59 28

29 24 206 78 60 59 28

Min & Max Poro. (%) 4 & 23 10&24 0 &22 5&29 5&28 20&33 0&25

Perm. (mD) 0&966 0.01&93 0&71.58 0.01&40.69 0.23&922.29 11.20&16632 0&120

Median Poro. (%) 7.29 13.72 4.96 16.80 13.75 26.60 14.56

Perm. (mD) 7.10 6.30 0.05 3.07 16.40 2506.16 1.90

Average Poro. (%) 11.26 13.15 6.60 16.35 13.81 26.48 14.23

Perm. (mD) 151.39 19.02 0.83 6.69 90.07 5114.42 13.93

Standard deviation Poro. Perm. (%) (mD) 6.54 274.85 6.09 26.22 4.81 5.08 4.83 9.27 6.15 198.68 2.58 4776.80 5.66 28.43

Based on the results, reservoir quality of the PGs in descending order is as the SC, Class 1, TVC, Class 2, MSC, and Class 3. The most frequent carbonate facies of the Asmari Formation (MF-7), owing to the prevalence of foraminifera, hence intraparticle pore spaces, makes the main building block of the SVC. The facies comprises a considerable part of the middle and upper Asmari succession. Porosity in the facies and resultant PG is high (the highest amount in the carbonates), but the permeability is low. Most other Asmari carbonate facies are mud-dominated thus belong to Class 3. The peritidal facies (MF-2) is the main constituent of the TVC, because of high fenestral porosity. Diagenesis has had a superior role in changing the primary sedimentary aspects of the carbonates, so that in many instances, for example in MF-6, cementation (mostly of anhydrite mineralogy) has shifted the position of rock form Class 1 to the others (Fig. 9a; Fig. 4a). In addition, dissolution has 13

had a remarkable impact on most facies of the formation, resulting in the alteration of original interparticle porosity, and in the privilege of the SVC and TVC classes. Even though here tectonically induced fractures have occurred in low intensity than other Asmari fields, where present, they have resulted in a connected network of predominant vuggy pore spaces (intrafossil & dissolution) and consequently in zones with proper permeability. Generally, the carbonate part of the formation in this field has good porosity, but low permeability due to an isolated network of pore spaces. The best reservoir quality belongs to the sandstone of the Ahwaz Member.

4.4.3. Stratigraphic modified Lorenz plot (SMLP) 4.4.3.1. Theoretical framework Gunter et al. (1997a) developed a graphical method that utilizes porosity, permeability and bed thickness to identify reservoir flow units. This reservoir characterization method is based on stratigraphic modified Lorenz plot (SMLP) in which in a Cartesian graph, cumulative storage capacity (Φh) defines the horizontal axis and cumulative flow capacity (kh) is the vertical axis:

∑

(8) ∑

(9)

Where k is permeability in milidarcies, h is the interval thickness and Φ is fractional porosity. What we require, in addition to the SMLP, to illustrate and verify the graphic method include a correlation curve (Gamma ray/GR, volume of clay/VCl, etc.), lithology and core description column, phi, k, pore throat radius (microns) at 35% mercury saturation (R35; Winland, 1972), k/phi ratio, %kh and %phih, all making a plot called stratigraphic flow profile (SFP). Finally, flow units determined on the SMLP are verified and illustrated on the SFP.

14

4.4.3.2 Flow units in the CK Field In the studied field, the primitive parameters required for constructing the SFP and SMLP were calculated using data from the two wells (Table 5).

Table 5. Parameters required for establishing stratigraphic flow profile (SFP) and stratigraphic modified Lorenz plot

DEPTH

PORO.

PORO.(V/V )

K

LOG R35

R35

K/PHI

KH

KH%

KH (CUMULA T)

PHIH

PHIH%

PHIH (CUMULA T)

(SMLP), wellCK#12, CK Field.

3438.81

5.46

0.05

0.10

-0.50

0.31

1.77

3439.10

7.25

0.07

0.07

-0.70

0.20

0.95

0.02

0.00

0.00

0.02

0.17

0.00

3439.16

0.13

0.13

-0.76

0.17

0.96

0.01

0.00

0.00

0.01

0.06

0.00

3439.31

13.1 0 9.05

0.09

0.16

-0.57

0.27

1.73

0.02

0.00

0.00

0.01

0.11

0.00

3439.45

8.87

0.09

0.07

-0.78

0.17

0.75

0.01

0.00

0.00

0.01

0.10

0.00

3439.52

7.49

0.07

0.08

-0.66

0.22

1.12

0.01

0.00

0.00

0.01

0.04

0.00

3440.15

0.11

0.26

-0.52

0.30

2.34

0.17

0.00

0.00

0.07

0.56

0.01

3440.23

11.2 4 7.63

0.08

0.11

-0.59

0.26

1.45

0.01

0.00

0.00

0.01

0.05

0.01

3440.62

5.55

0.06

0.92

0.07

1.17

16.61

0.36

0.00

0.00

0.02

0.17

0.01

3440.85

4.42

0.04

2.82

0.44

2.75

63.94

0.65

0.00

0.00

0.01

0.08

0.01

3442.05

26.2 9 15.4 9 16.0 4 16.3 9 18.6 9 16.2 4

0.26

0.39

2.44

0.32

2.49

0.04

3.66

0.08

0.00

0.09

0.67

0.04

-0.04

0.91

37.8 4 15.9 4 0.57

0.00

0.56

119.9 3 187.1 1 17.69

0.19

0.16

31.5 4 28.9 8 2.84

0.00

0.00

0.03

0.25

0.05

0.16

0.88

-0.35

0.45

5.35

0.04

0.00

0.00

0.01

0.05

0.05

0.19

6.17

0.10

1.25

33.03

0.80

0.00

0.00

0.02

0.19

0.05

0.16

5.86

0.14

1.37

36.10

0.70

0.00

0.00

0.02

0.15

0.05

3442.60 3442.80 3442.84 3442.97 3443.09

0.15

According to the SMLP, four and five flow unites are recognized in the wellCK#8 & wellCK#12, respectively. As seen in Fig. 10, in the wellCK#8, FU-2 and FU-4 have the best reservoir qualities making the speed zones of the well, whereas FU-1 and FU-3 represent the baffle zones. In stratigraphic point of view, the speed zones are coincident with the Ahwaz sandstones and the baffles

15

are correspondent to the carbonates. In spite of appropriate storage capacity, the carbonates have poor quality, because of their low permeability; accordingly, the reservoir has been majorly established in the siliciclastic part. In the wellCK#12, FU-2 and FU-4 are the speed zones, while FU-1, FU-3 and FU-5 make the baffles. In this well, again, the sandstones represent the best quality whereas the carbonates have low permeability, regardless of their high storage capacity (Table 6).

Table 6. Storage capacity and flow capacity of flow unites identified in the wellCK#8 and wellCK#12, CK Filed. WELLCK#8

WELLCK#12

FLOW

Storage Capacity

Flow Capacity

Storage Capacity

Flow Capacity

UNIT

(%)

(%)

(%)

(%)

FU-1

0.82

15.36

1.69

49.51

FU-2

27.94

25.04

8.03

12.39

FU-3

1.17

17.44

0.86

17.88

FU-4

70.06

42.16

89.38

15.09

FU-5

-

-

0.06

2.45

5. Discussion 5.1. Juxtaposing different reservoir characterization methods Figs. 11 and 12 illustrate the integration of the three methods, where they are presented alongside each other. The correlation of the methods indicates they have good agreement and can be used to establish a reservoir zonation for the field. For example, FU-1 in the wellCK#8 shows a poor quality while the storage capacity is about 16%. According to the FZI method, the unit is dominated by the HFZ3 and HFZ4, also is majorly correspond to Class 3 of the L

’

T

applied show a poor reservoir quality for this unit. FU-2 is relatively dominated by the HFZ2 or the SC, in most of its extension. All the methods signify the unit has high quality and makes a speed zone in the reservoir. FU-3, in most of its interval, is dominated by the HFZ3 and HFZ4, likewise by Class 3 and the MSC based on the L

’ method, all indicating a poor reservoir quality for it. FU-4, as the 16

main speed zone of the well, is predominantly composed of the highest quality HFZ1 and HFZ2 according to the FZI method or the SC based on the L

’

I the wellCK#12, similarly

same correlations can be observed. Here, FU-1 is in coincidence with the HFZ2 and HFZ3, as well with Class 3 and the SVC. The situation has resulted in a high porosity, but low permeability. In contrary, FU-4 consists of the HFZ1 or the SC, leading to a high reservoir quality for the unit. Based on the results, it can be concluded there is a good agreement between different reservoir characterization methods. However, the SMLP method seems to be the best method for the zonation of a reservoir, because the resultant units are mapable across the field. In contrary, the other methods give rise to such small scale units that only can be regarded as rock types, not flow units, and they should be integrated with the SMLP to identify precise reservoir zones in a reservoir (cf., Ebanks Jr et al., 1993).

5.2. Reservoir zonation of the Cheshmeh-Khosh oil field Integrating geologic (sedimentology and sequence stratigraphy) information with different reservoir characterization methods, a new applicable reservoir zonation is presented for the Asmari Formation in this filed (Figs. 11, 12). It should be mentioned in the two wells studied, direct core poro-perm data were available for most of the carbonate part while only for a few meters of the siliciclastics. Therefore, for a meaningful reservoir zonation, it was necessary to acquire or predict the reservoir petrophysical properties of the rest part of the siliciclastics with alternative procedures. For the purpose, we used the k-phi relationship obtained from the available sandstone data via using the FZI method. As seen in Fig. 8d, this relationship for the HFZ2 that represents the sandstones of the siliciclastic part of the field is as below: (10) Where y is permeability and x in porosity. With this equation in hand, and placing the porosity data acquired form porosity logs in it, we could obtain a reasonable estimate of permeability in those intervals with no direct poro-perm data. Consequently, we were able to appraise a more accurate 17

image of the configuration of petrophysical properties and thus the reservoir flow zones in the CK field. The dashed lines in Figs 11, 12 represent estimated parameters in such the intervals. The integrated reservoir zones presented here are precisely correlatable across the field using well logs, so that a 3D picture of the distribution of different units in the field can be achieved (Fig. 13). In this regard, five reservoir zones are distinguished: Zone#1 is equivalent to major part of the Ahwaz Sandstone Member, where the highest reservoir quality is detected. Above the succession, there is an interval of the interbedded shale and carbonates showing lower quality, making the second zone of the reservoir (Zone#2). Up to the wells, another porous and permeable pure sandstone unit appears, which marks the second speed zone and the third reservoir zone of the field (Zone #3). The zones#4&5 are comparable to the carbonates of the formation and make the least quality zones. However, the lower unit (#4) shows a relative higher quality than the other does. These zones represent the baffle zones across the field, regardless of their high storage capacity. The evaporite-bearing Gachsaran Formation seals the reservoir. The three lower zones were created as a result of changing primary sedimentary settings, whereas the two upper zones are mostly the product of diagenetic processes.

5.3 Reservoir zonation in sequence stratigraphic framework Three of the five reservoir zones of the CK Field are the product of sea-level changes and are thoroughly comparable to the sequence stratigraphic framework of the formation (Figs. 11, 12). Zone#1 is connected to the falling stage of sea level (FSST). During the stage, noticeable amounts of sands were being delivered to the Asmari Basin, generating the best reservoir zone of the formation, in reservoir quality point of view. After the FSST and during the next LST (lowstand systems tract) and TST (transgressive systems tract), the amount of the terrigenous sediments reduced, triggering carbonate factory to produce carbonate precipitations. As a result, a reservoir zone with the alternation of shale and carbonates showing low reservoir quality was deposited on Zone#1. The falling stage of this sequence again provided opportunity for siliciclastics to infiltrate into the basin. This falling stage systems tract made the third zone of the field, maintaining as good reservoir quality as the lower

18

sandstone unit. The two upper reservoir zones of the field seems to be irrelevant to sea level fluctuations, and their creation is more related to diagenetic. However, this study, in association with previous ones (Aqrawi et al., 2006; Ehrenberg et al., 2007; van Buchem et al., 2010) show, in the upper carbonate part of the Asmari Formation, the accommodation space reduced successively upward, leading to the increase of evaporative conditions up to the section, resulted in producing penecontemporaneous brines capable of dissolving underlying strata. These brines caused the formation of substantial dissolution and vuggy pore spaces in the carbonate unit. Consequently, although these two reservoir units are not originally sedimentary-related, their reservoir characteristics are highly inherited from see level-induced diagenetic events. A remarkable point is that the systems tracts and other sequence stratigraphic features show an obvious impact on the well logs thus can be used for extrapolating similar units across the field (Fig. 13).

6. Conclusions Integration of the reservoir rock classification method developed by Lucia (1995) and the Flow Zone Indicator (FZI) method with the reservoir flow unit determination method proposed by Gunter et al. (1997a) resulted in a field-scaled reservoir zonation for the Asmari Formation in the CheshmehKhush Field. The comparison of the methods showed their results are in good agreement with each other: the main speed zones of the field are dominantly composed of the best hydraulic flow zones, based on the FZI method (HFZ1 & HFZ2), similarly, of the best petrophysical groups, based on the L

’

(SC C

-1). In contrary, the baffle zones are comparable with poor quality reservoir

rock types in the rock typing methods. The best reservoir zones (speed zones) of the field are equivalent to the marginal marine sandstones of the Ahwaz Sandstone Member, where their distribution was controlled by relative sea level changes: the erosion of heights prior and/or simultaneous to the Red Sea spreading resulted in generating fluvial systems on the Arabian Plate that were infiltrating sand to the Asmari Basin during lowered sea level, making a deltaic system in the SW margin of the basin. Succeeding transgressions 19

resulted in declining or ceasing the sand supply, as well as in the re-establishment of the carbonate factory. The carbonates of the Asmari Formation have relatively good porosity owing to early diagenetic dissolution, but they show poor permeability, because the pores are an isolated network of vugs.

Acknowledgements The Institute for Advanced Studies in Basic Sciences (IASBS) provided facilities for this research, for which the authors are grateful. National Iranian Oil Company (NIOC) and the University of Tehran are thanked for their support and data preparation. Our special thanks go to Professor A. Amini form the University of Tehran and three anonymous referees for their useful comments and corrections, which have considerably improved the original manuscript.

References Abbaszadeh, M., Fujii, H. and Fujimoto, F., 1996. Permeability prediction by hydraulic flow units Theory and applications. SPE Formation Evaluation, 11(4): 263-271. Adams, C.G. and Bourgeois, E., 1967. Asmari biostratigraphy. Iranian Oil Operation Companies, Geological and Exploration Division, 1074: 1-74. Adams, T.D., 1969. The Asmari Formation of Lurestan and Khuzestan Provinces. IOOC Report(1154): 34. Ahmadhadi, F., Lacombe, O. and Daniel, J.-M., 2007. Early reactivation of basement faults in central Zagros (sw iran): Evidence from pre-folding fracture populations in Asmari Formation and Lower Tertiary paleogeography. In: O. Lacombe, F. Roure, J. Lavé and J. Vergés (Editors), Thrust Belts and Foreland Basins. Frontiers in Earth Sciences. Springer Berlin Heidelberg, pp. 205-228. Ahr, W.M., 2008. Geology of carbonate reservoirs : the identification, description, and characterization of hydrocarbon reservoirs in carbonate rocks. Wiley, Hoboken, N.J., 277 pp. Ala, M.A., 1982. Chronology of trap formation and migration of hydrocarbons in Zagros sector of southwest Iran. American Association of Petroleum Geologists Bulletin, 66(10): 1535-1541. Alavi, M., 1994. Tectonics of the zagros orogenic belt of iran: new data and interpretations. Tectonophysics, 229(3-4): 211-238. Alavi, M., 2004. Regional stratigraphy of the Zagros fold-thrust belt of Iran and its proforeland evolution. American Journal of Science, 304(1): 1-20. Alavi, M., 2007. Structures of the Zagros fold-thrust belt in Iran. American Journal of Science, 307(9): 1064-1095. Alsharhan, A.S. and Nairn, A.E.M., 1997. Sedimentary basins and petroleum geology of the Middle East. Elsevier, Amsterdam ; New York, 843 pp.

20

Amaefule, J.O., Altunbay, M., Tiab, D., Kersey, D.G. and Keelan, D.K., 1993. Enhanced reservoir description: Using core and log data to identify hydraulic (flow) units and predict permeability in uncored intervals/wells. Proceedings - SPE Annual Technical Conference and Exhibition. Amirshahkarami, M., Vaziri-Moghaddam, H. and Taheri, A., 2007. Paleoenvironmental model and sequence stratigraphy of the Asmari Formation in southwest Iran. Historical Biology, 19(2): 173-183. Aqrawi, A.A.M. et al., 2006. The origin of dolomite in the Asmari Formation (oligocene-lower miocene), dezful embayment, SW Iran. Journal of Petroleum Geology, 29(4): 381-402. Archie, G.E., 1950. Introduction to petrophysics of reservoir rocks. American Association of Petroleum Geologists Bulletin, 34(5): 943-961. Berberian, M. and King, G.C.P., 1981. Towards a paleogeography and tectonic evolution of Iran. Canadian journal of earth sciences, 18(2): 210-265. Beydoun, Z.R., Clarke, M.W.H. and Stoneley, R., 1992. Petroleum in the Zagros Basin: a late Tertiary foreland basin overprinted onto the outer edge of a vast hydrocarbon-rich PaleozoicMesozoic passive-margin shelf. Foreland basins and fold belts: 309-339. Burchette, T.P. and Wright, V.P., 1992. Carbonate ramp depositional systems. Sedimentary Geology, 79(1-4): 3-57. Busk, H.G. and Mayo, H.T., 1918. Some notes on the geology of the Persian oilfields. Journal Institute Petroleum Technology, 5(17): 5-26. Buxton, M.W.N. and Pedley, H.M., 1989. Short paper: a standardized model for Tethyan Tertiary carbonate ramps. Journal - Geological Society (London), 146(5): 746-748. Carman, P.C., 1937. Fluid flow through granular beds. AIChE Journal, 15: 150-166. Clerke, E.A., 2010. Permeability and Microscopic Displacement Efficiency of M_1 Bimodal Pore Systems in Arab-D Limestone. SPE, SAUDI ARAMCO. Daraei, M., Amini, A. and Ansari, M., 2015. Facies analysis and depositional environment study of the mixed carbonate–evaporite Asmari Formation (Oligo-Miocene) in the sequence stratigraphic framework, NW Zagros, Iran. Carbonates and Evaporites, 30(3): 253-272. Dercourt, I. et al., 2000. Atlas Peri-Tethys Palaeogeographical Maps, 24 Maps and Explanatory Note. CCGM/CGMW, Paris. Dickson, J.A.D., 1965. A Modified staining technique for carbonates in thin section [7]. Nature, 205(4971): 587. Dunham, R.J., 1962. Classification of carbonate rocks according to depositional texture. American Association of Petroleum Geologists Memoir, 1: 108-121. Ebanks Jr, W., Scheihing, M. and Atkinson, C., 1993. Flow units for reservoir characterization. Development geology reference manual: AAPG Methods in Exploration Series, 10: 282-285. Ebanks Jr, W.J., 1987. Flow unit concept-integrated approach to reservoir description for engineering projects. AAPG Meeting Abstracts, 1(5): 521-522. Ehrenberg, S.N. et al., 2007. Strontium isotope stratigraphy of the asmari formation (Oligocene Lower miocene), SW Iran. Journal of Petroleum Geology, 30(2): 107-128. Embry, A.F. and Klovan, J.E., 1971. A late Devonian reef tract on northeastern Banks Island, Northwest Territories. Bulletin of Canadian Petroleum Geology, 19(4): 730-781. Falcon, N.L., 1961. Major earth-flexuring in the Zagros mountains of south-west Iran. Quarterly Journal of the Geological Society of London, 117(1-4): 367-376. Falcon, N.L., 1974. Southern Iran: Zagros Mountains, pp. 199-211. Farzipour-saein, A., Yassaghi, A., Sherkati, S. and Koyi, H., 2009. Basin evolution of the Lurestan region in the zagros fold-and-thrust belt, Iran. Journal of Petroleum Geology, 32(1): 5-19. f f b : p pp Sp Berlin ; New York, 976 pp. Gharechelou, S., Daraei, M. and Amini, A., 2016. Pore types distribution and their reservoir properties in the sequence stratigraphic framework: a case study from the Oligo-Miocene Asmari Formation, SW Iran. Arabian Journal of Geosciences, 9(3): 194. Ghazban, F., 2007. Petroleum geology of the Persian Gulf. Tehran University, Tehran, 717 pp.

21

Gunter, G.W., Finneran, J.M., Hartmann, D.J. and Miller, J.D., 1997a. Early determination of reservoir flow units using an integrated petrophysical method. Proceedings - SPE Annual Technical Conference and Exhibition, Omega(Pt 1): 373-380. Gunter, G.W., Pinch, J.J., Finneran, J.M. and Bryant, W.T., 1997b. Overview of an integrated process model to develop petrophysical based reservoir descriptions. Proceedings - SPE Annual Technical Conference and Exhibition, Omega(Pt 2): 475-479. Hamon, G. and Bennes, M., 2004. Two-phase flow rock typing: Another approach. Petrophysics, 45(5): 433-444. Haynes, S.J. and McQuillan, H., 1974. Evolution of the Zagros suture zone, Southern Iran. Bulletin of the Geological Society of America, 85(5): 739-744. Hearn, C.L., Ebanks Jr, W.J., Tye, R.S. and Ranganathan, V., 1983. Geological factors influencing reservoir performance of the hartzog draw field, wyoming, Society of Petroleum Engineers of AIME, (Paper) SPE. Heydari, E., 2008. Tectonics versus eustatic control on supersequences of the Zagros Mountains of Iran. Tectonophysics, 451(1-4): 56-70. Homke, S., Vergés, J., Garcés, M., Emami, H. and Karpuz, R., 2004. Magnetostratigraphy of Miocene-Pliocene Zagros foreland deposits in the front of the Push-e Kush Arc (Lurestan Province, Iran). Earth and Planetary Science Letters, 225(3-4): 397-410. Honarmand, J. and Amini, A., 2012. Diagenetic processes and reservoir properties in the ooid grainstones of the Asmari Formation, Cheshmeh Khush Oil Field, SW Iran. Journal of Petroleum Science and Engineering, 81: 70-79. Hunt, D. and Tucker, M.E., 1992. Stranded parasequences and the forced regressive wedge systems tract: deposition during base-level'fall. Sedimentary Geology, 81(1-2): 1-9. Jackson, J. and McKenzie, D., 1984. Active tectonics of the Alpine- Himalayan Belt between western Turkey and Pakistan. Geophysical Journal - Royal Astronomical Society, 77(1): 185-264. James, G. and Wynd, J., 1965. Stratigraphic nomenclature of Iranian oil consortium agreement area. American Association of Petroleum Geologists Bulletin, 49(12): 2182-2245. Kavoosi, M.A. and Sherkati, S., 2012. Depositional environments of the Kalhur Member evaporites and tectonosedimentary evolution of the Zagros fold-thrust belt during Early Miocene in south westernmost of Iran. Carbonates and Evaporites, 27(1): 55-69. Kozeny, J., 1927. Über kapillare Leitung des Wassers im Boden. Royal Academy of Science, Vienna, Proc. Class I, 136: 271-306. Laursen, G. et al., 2006. Reassessment of the age of the Asmari Formation, Iran. Abstract, Forums: 10-15. Laursen, G.V. et al., 2009. The Asmari Formation revisited: Changed stratigraphic allocation and new biozonation. Shiraz, First International Petroleum Conference & Exhibition, European Association of Geoscientists and Engineers. Lees, G.M., 1933. The reservoir rocks of Persian oil fields. American Association of Petroleum Geologists Bulletin, 17(3): 229-240. Lucia, F.J., 1983. Petrophysical parameters estimated from visual description of carbonate rocks: A field classification of carbonate pore space. Journal of Petroleum Technology, 35(3): 626637. Lucia, F.J., 1995. Rock-fabric/petrophysical classification of carbonate pore space for reservoir characterization. American Association of Petroleum Geologists Bulletin, 79(9): 1275-1300. Lucia, F.J., 1999. Carbonate reservoir characterization. Springer, Berlin ; New York, 226 pp. Lucia, F.J., 2007. Carbonate reservoir characterization : an integrated approach. Springer, Berlin ; New York, 336 pp. Martin, A.J., Solomon, S.T. and Hartmann, D.J., 1997. Characterization of petrophysical flow units in carbonate reservoirs. AAPG Bulletin, 81(5): 734-759. Masaimeh, S.K., Shiekah, I.A. and Jing, X.D., 2007. Improved characterization and modeling of capillary transition zones in carbonate reservoirs. SPE Reservoir Evaluation and Engineering, 10(2): 191-204. Masalmeh, S.K. and Jing, X., 2007. Improved Characterisation And Modelling Of Carbonate Reservoirs For Predicting Waterflood Performance. International Petroleum Technology Conference. 22

McQuillan, H., 1985. Fracture-controlled production from the Oligo-Miocene Asmari Formation in Gachsaran and Bibi Hakimeh Fields, SW Iran. Carbonate Petroleum Reservoirs: 513-523. Mossadegh, Z.K., Haig, D.W., Allan, T., Adabi, M.H. and Sadeghi, A., 2009. Salinity changes during Late Oligocene to Early Miocene Asmari Formation deposition, Zagros Mountains, Iran. Palaeogeography, Palaeoclimatology, Palaeoecology, 272(1-2): 17-36. Motiei, H., 1993. Stratigraphy of Zagros. Treatise on the Geology of Iran, 1. Ministry of Mines and Metals, Geological Survey of Iran, Tehran, Iran, 583 pp. Pedley, M., 1998. A review of sediment distributions and processes in Oligo-Miocene ramps of southern Italy and Malta (Mediterranean divide), Geological Society Special Publication, pp. 163-179. Pomar, L., 2001. Types of carbonate platforms: A genetic approach. Basin Research, 13(3): 313-334. Sepehr, M. and Cosgrove, J.W., 2004. Structural framework of the Zagros Fold-Thrust Belt, Iran. Marine and Petroleum Geology, 21(7): 829-843. Seyrafian, A., 2000. Microfacies and depositional environments of the Asmari formation, at Dehdez area (a correlation across Central Zagros Basin). Carbonates and Evaporites, 15(2): 121-129. Sharland, P.R., 2001. Arabian plate sequence stratigraphy. Gulf PetroLink, Manama, Bahrain, 371 p. pp. Sherkati, S. and Letouzey, J., 2004. Variation of structural style and basin evolution in the central Zagros (Izeh zone and Dezful Embayment), Iran. Marine and Petroleum Geology, 21(5): 535554. Stocklin, J., 1968. Structural history and tectonics of Iran. American Association of Petroleum Geologists Bulletin, 52(7): 1229-1258. Stoneley, R., 1981. The geology of the Kuh-e Dalneshin area of southern Iran, and its bearing on the evolution of southern Tethys. Journal of the Geological Society, 138(5): 509-526. Takin, M., 1972. Iranian geology and continental drift in the Middle East. Nature, 235(5334): 147150. van Buchem, F.S.P. et al., 2010. Regional stratigraphic architecture and reservoir types of the OligoMiocene deposits in the Dezful Embayment (Asmari and Pabdeh Formations) SW Iran, Geological Society Special Publication, pp. 219-263. Vaziri-Moghaddam, H., Kimiagari, M. and Taheri, A., 2006. Depositional environment and sequence stratigraphy of the Oligo-Miocene Asmari Formation in SW Iran. Facies, 52(1): 41-51. Wilson, J.L., 1975. Carbonate facies in geologic history. Springer-Verlag, Berlin ; New York, 471 pp. Winland, H., 1972. Oil accumulation in response to pore size changes, Weyburn field, Saskatchewan (unpublished). F72-G-25, Amoco Production Company, Tulsa, OK. Ziegler, M.A., 2001. Late Permian to Holocene paleofacies evolution of the Arabian Plate and its hydrocarbon occurrences. GeoArabia, 6(3): 445-504.

Figure captions Fig. 1 a) Location map of the study area in SW Iran and tectonostratigraphic subdivisions of the Zagros Fold-Thrust Belt (modified from Farzipour-saein et al., 2009). The studied field is located in the Dezful Embayment, and the surface sections are in the Lurestan Salient. b) geologic map of the study area showing main lithostratigraphic units and anticlines of the region. c) lithostratigraphic columns representing the Asmari Formation in two different structural zones (i.e., the Dezful Embayment and the Lurestan Salient), where two different members of the formation referred to as

23

the Ahwaz Sandstone Member and Kalhur Evaporitic Member are extended. The study is mainly based on data form a field located in the Dezful Embayment with some correlative surface sections in the Lurestan Zone. Fig. 2 A plate representing microfacies and petrofacies of the Asmari Formation across the studied area. One evaporite facies (MF-1), nine carbonates (MFs 2-10) and one siliciclastic petrofacies (PF-1) are recognized. The characteristics of the facies are presented in Table 1. Fig. 3 Paleogeographic and paleodepositional models of the Asmari Basin. a) paleogeographic map showing the Oligo-Miocene foreland basin developed between the Arabian Plate and Iranian plates at the time (modified from Dercourt et al., 2000). The Asmari Formation was deposited in such a basin where most of the shallow marine NW-SE trending trench was dominated by carbonate deposition, but two other depositional systems, namely the Kalhur evaporitic sub-basin and Ahwaz siliciclastic marginal delta were also present at the time. b) paleofacies and paleogeographic map showing the evaporite and siliciclastic depositional loci of the Asmari Formation (modified from Adams, 1969). c) depositional model of the Asmari carbonate ramp as the dominant depositional system of the basin. Fig. 4 Main diagenetic features of the Asmari Formation in the CK Field. a) micritization in ooid grainstone (MF-6) with later diagenetic anhydrite cement between the ooids showing even distribution. b) preferential dolomitization in ooid grainstone facies (MF-6) with an unaffected matrix. A marine micritization probably made the ooids more susceptible to dolomitization. c) thin coatings of micrite around the bioclasts have made them more persistent to later dissolution than interior aragonitic parts, resulting in developing biomolds in the bioclastic packstone facies (MF-7). The molds and some interparticle spaces are then filled with early diagenetic dolomite cement. d) medium crystalline dolomites resulted in early diagenetic evaporative dolomitization in the lime mudstone facies (MF-2). e) close-up view of chicken-wire texture showing part of an anhydrite nodule and dolomite partings. The co-occurrence of evaporites and dolomites points to a probable evaporative model for the dolomitization of the strata. MF-2. f) preferential dissolution of ooids producing oomolds in a dolomitized ooid packstone sample (MF-6). Original aragonite mineralogy of the ooids 24

resulted in their dissolution while the matrix with high-Mg calcite mineralogy was converted to dolomite during later diagenesis. g) development of biomolds in bioclastic wacke-packstone facies due to dissolution (MF-7). Some interior spaces of the cortoids (coated bioclasts) and interparticle spaces are then filled with early diagenetic dolomite cement. h) early diagenetic dolomite cementation in a peloid bioclast grainstone (MF-7). Some inter- and intraparticle pore spaces are then filled with early diagenetic dolomite cement. i) isopachous rim cement around the grains (mostly dissolved ooids) with red-stained replacive calcite mineralogy (aragonite originally). Dolomite rhombs of later diagenetic origin are unaffected by the staining. j) late diagenetic equant calcite cement with drusy fabric, filling interparticle pore spaces in a bioclastic foraminifer packstone (MF-3). k) late diagenetic anhydrite cement developing on an early diagenetic dolomite cement (MF-7). l) fitted fabric caused by physio-chemical compaction of ooids in the ooid grainstone facies (MF-6). Some anhydrite cements with patchy distribution are also present. Fig. 5 Sequence of diagenetic events of the Asmari Formation in the studied area. The formation has experienced marine/hypersaline, meteoric and burial diagenetic environments during its adventure. The most effective porosity enhancing processes are early diagenetic dissolution and dolomitization, and partially, late diagenetic fracturing. In contrary, the most porosity occluding processes are early diagenetic dolomite cementation and late diagenetic cementation, especially of anhydrite mineralogy. The exposure phase and evaporite diagenesis are related to the outcrops in SW Lurestan. Fig. 6 Sequence stratigraphy of the Asmari Formation in the CK Field and its correlation with a representative outcrop from SW Lurestan where the Kalhur Evaporitic Member is extended. The deposition of the Asmari Formation in the Lurestan Zone occurred later than the Dezful Embayment. Four and half sequences are recognized in the latter whereas three ones in the former. Fig. 7 Graphs used for the identification of hydraulic flow zones (HFZ) based on the FZI method. a, b) histograms showing distribution of the FZI in the wellCK#8 & wellCK#12. c, d) probability plots for the determination of the FZI ranges in different HFZ of the wellCK#8 & wellCK#12. e, f)

25

log-log plots of the RQI versus PhiZ in which different HFZs of the wellCK#8 & wellCK#12 are displayed. Fig. 8 Graphs showing k-phi relationships in the wellCK#8 & wellCK#12. a, b) k versus phi and resultant k-phi relationships for the wellCK#8 and wellCK#12. c, d) k-phi relationships for different HFZs of the wellCK#8 & wellCK#12. Fig. 9 Graphs used for the identification of petrophysical groups (reservoir rock types) based on the Lucia’ method. a) three petrophysical classes/groups recognized in carbonates with dominant interparticle pore spaces. b) two petrophysical classes recognized in carbonates with dominant vuggy pore spaces. c) petrophysical classes identified in the siliciclastics of the Asmari reservoir. Fig. 10 Stratigraphic modified Lorenz plots (SMLPs) for the CK#8 and CK#12. For storage capacity and flow capacity of each flow unit (FU) see Table 6. Fig. 11 Stratigraphic Flow Profile (SFP; Gunter et al., 1997) plotted against Hydraulic Flow Zones (RQI method) and petrophysical groups (PG; Lucia’ method) to identify different reservoir zones of the CK#8. Five reservoir zones are distinguished in this well with integrating the method. The sequence stratigraphy of the well is also illustrated. Fig. 12 Stratigraphic Flow Profile (SFP; Gunter et al., 1997) illustrated against Hydraulic Flow Zones (RQI method) and petrophysical groups (PG; Lucia’ method) to identify different reservoir zones of the CK#12. Five reservoir zones are distinguished in this well with integrating the method. The sequence stratigraphy of the well is also illustrated. Fig. 13 Scheme illustrating the reservoir zonation of the Cheshmeh-Khush petroleum field in some representative wells of the field.

26

Highlights 

 



This study focuses on reservoir rock classification of the most prolific reservoir rock of the Zagros Mountains in order to introduce a field-scaled reservoir zonation in sequence stratigraphic framework. an integration of three different reservoir rock classification methods is applied to identify speed and/or baffle zones of the reservoir. The best reservoir zones (speed zones) of the field are equivalent to the marginal marine sandstones of the Ahwaz Sandstone Member that their distribution was controlled by relative sea level changes. The carbonates have relatively good porosity, but they show poor permeability, because the pores are an isolated network of vugs, thus they make the baffle zones of the field.

27

28

29

30

31

32

33

34

35

36

37

38